Adapting to Lower Cost Natural Gas

MD’s Energy Economics and Technology Committee is a resource center for individuals with interests in business, planning and forecasting aspects of the energy industries.

While oil has long been a dominant agent in global and national economies – particularly at $100 per barrel – natural gas is the most important fuel to changes taking place in the energy economy.

These changes are greater than anyone could have imagined and are far reaching.

Among producers, necessity (i.e., how to survive with low natural gas prices) has been the mother of financial invention, and particularly of joint venture financial arrangements bringing money into development and production.

The gas-directed rig count from 2000 to 2006 experienced an initial spurt followed by sustained increases. Production generally declined and LNG was widely expected to serve as the only major source of incremental supply until Arctic gas pipelines were completed. Since 2008, both prices and rig counts collapsed while annual production has grown 1.5 to 2.0 billion cubic feet per day. Financial arrangements, horizontal drilling and other procedures in core regions have improved productivity while leasing terms (to hold leases by production) have sustained drilling under falling prices. During 2010, a shift in the mix to oil-rich plays also has contributed to co-product oil and gas production, stabilizing the level of drilling even PLATT as prices continued to decline.

In a perverse manner, this kind of financing decouples production (up) from prices (down), exacerbating the oversupply that forced creative steps in the first place. These divergent paths are summarized in the accompanying chart.

Related inventions are the unheard-of concepts of exporting LNG or even entertaining gas to liquids, both possible means to “monetize” shale production.

Among buyers of natural gas, particularly the power industry, low gas prices have translated into low electricity prices. Although good for consumers, these deteriorate power generators’ balance sheets just when economic recovery is improving sales.

Most unusual in that sector, however, is the flip-flop in cost competitiveness of coal and gas-fired generation. Displacement of coal by gas broke all historic records through most of 2009. It quite likely exceeded those records last year and may reach even greater heights in 2011. While occurring principally in eastern and southeastern states, this kind of fuel switching alone helps prop up natural gas demand nationally by a number averaging about one to 1.5 billion cubic feet per day.

A contributing factor has been global escalation of metallurgical and thermal coal prices – not only has gas-fired generation benefited from low prices, but coal generation has incurred a premium.

Current solid fuel markets look a lot like those in 2008, when we experienced the global commodities supercycle.

Looking farther ahead, the impact of unconventional supplies – and especially the growth in reserves and resources of shale gas – can hardly be overstated. Due to their relatively low capital costs and high efficiencies, natural gas in combined cycle applications is the dominant economic benchmark for virtually all electric generation investments, affecting choices across the technology spectrum from wind and solar to nuclear or coal with carbon capture plus sequestration.

Because of compelling economics, commitments to natural gas are growing while wind projects face far worse returns than expected.

A widely accessible barometer of new attitudes toward natural gas is the Energy Information Administration’s Annual Energy Outlook, whose 2015 Henry Hub estimate is below $5/million Btu, and 2020 estimate is a mere $5.18, or $1.46 below its prior estimate and $2.29 below the year before that.

This change in thinking has tended to track the forward curve, whose decline has been nothing but remarkable, dropping about $1.50 in the first 10 months of 2010 (about the time that EIA’s forecasters are completing their next update).

No doubt these, as all forecasts, will be proven wrong. Major wildcards are the price of natural gas at some new equilibrium and the level of demand (we must keep a close eye on retirements of coal-fired capacity in the intermediate term and on the fate of non-gas options such as nuclear in the long term).

In the EE&T Committee’s annual report, authors review these and additional topics. As principal author, I am indebted to contributions from natural gas industry consultants George Lippman and James T. Jensen, to special consultant Dieter Bieke and to the Electric Power Research Institute.

Results of economic modeling of gas shales are presented with an open invitation to members to provide data-backed analyses that will further our understanding of play economics under varying assumptions. The big-ticket items are the first years of production and the magnitude of drilling and completion costs, affecting both breakeven prices and years to payback.

Oil also makes a huge difference, suggested to improve Eagle Ford economics by an amount equivalent to a $2 per million Btu increase in the price of natural gas.

Unfortunately, no plays offer the multi-year history provided by the Barnett Shale, meaning much rides on assumptions.